Process for removal of hydrogen sulphide and carbon dioxide from an acid gas stream

ABSTRACT

A process for removal of H 2 S and CO 2  from an acid gas stream comprising H 2 S and CO 2 , the process comprising the steps of: (a) reacting H 2 S in the acid gas stream with SO 2  to form sulphur vapour and water vapour, thereby obtaining a first off-gas stream comprising CO 2 , water vapour, sulphur vapour, residual SO 2  and residual H 2 S; (b) converting residual SO 2  in the first off-gas stream to H 2 S in a first off-gas treating reactor, thereby obtaining a second off-gas stream depleted in SO 2  and enriched in H 2 S and CO 2  compared to the first off-gas stream; (c) contacting the second off-gas stream with an H 2 S absorbing liquid, thereby transferring H 2 S from the gas stream to the H 2 S absorbing liquid to obtain H 2 S absorbing liquid enriched in H 2 S and a third off-gas stream enriched in CO 2 ; (d) removing CO 2  from the third off-gas stream by contacting the third off-gas stream with CO 2  absorbing liquid in a CO 2  absorber, thereby transferring CO 2  from the third off-gas stream to the CO 2  absorbing liquid to obtain CO 2  absorbing liquid enriched in CO 2  and purified gas.

The invention relates to a process for removal of hydrogen sulphide(H₂S) and carbon dioxide (CO₂) from an acid gas stream.

A process known in the art for removal of H₂S from a gas stream uses thepartial oxidation of H₂S to SO₂ according to:

2H ₂ S+30₂→2H ₂ O+2SO ₂  (1)

The SO₂ formed can be (catalytically) converted to elemental sulphuraccording to the Claus reaction:

2H ₂ S+SO ₂→2H ₂ O+3/n S _(n)  (2)

The combination of reactions (1) and (2) is known as the Claus process.The Claus process is frequently employed both in refineries and for theprocessing of H₂S recovered from natural gas.

The Claus process results in a gas still comprising unreacted H₂S and/orSO₂. Increasingly rigorous standards concerning the protection of theenvironment make simple venting or incineration of the final gas streaman unattractive or impermissible choice. Thus, the Claus tail gas isgenerally passed to a tail gas clean up unit, which is able toeffectively remove H₂S or SO₂, notwithstanding their low concentration.A number of commercially available tail gas clean up processes are knownin the art. For example, in U.S. Pat. No. 6,962,680 a process isdescribed for removing sulphur compounds from a gas comprising besidesH₂S also a substantial amount of carbon dioxide. The gas is separatedinto a concentrated gas containing H₂S and a residual gas containingcarbon dioxide, mercaptans and aromatic compounds. The concentrated gasis transferred to a Claus reaction process in which the H₂S is recoveredas elemental sulphur. Off-gas discharged from the Claus reaction isheated and mixed with the residual gas; the resultant mixture istransferred to a hydrogenation reactor where residual sulphur compoundsare converted to H₂S. Thus-formed H₂S is separated using anabsorption-regeneration step. Gas exiting the regeneration step isreturned to the Claus reaction. A disadvantage of the process describedin U.S. Pat. No. 6,962,680 is that the gas leaving the regenerationtower, which contains besides hydrogen sulphide also a substantialamount of carbon dioxide, is returned to the Claus sulphur recoveryunit. This results in dilution of the Claus feed gas and a lower rate ofthe Claus reaction.

Furthermore, the process described in U.S. Pat. No. 6,962,680 results ina considerable emission of carbon dioxide into the atmosphere from theabsorption step. During the last decades there has been a substantialglobal increase in the amount of CO₂ emission to the atmosphere.Following the Kyoto agreement, CO₂ emission has to be reduced in orderto prevent or counteract unwanted changes in climate.

Thus, there remains a need in the art for a process enabling removal ofH₂S and CO₂ from an acid gas stream comprising H₂S and CO₂, both inconsiderable amounts, wherein emission of CO₂ into the atmosphere isreduced to a minimum.

To this end, the invention provides a process for removal of H₂S and CO₂from an acid gas stream comprising H₂S and CO₂, the process comprisingthe steps of:

(a) reacting H₂S in the acid gas stream with SO₂ to form sulphur vapourand water vapour, thereby obtaining a first off-gas stream comprisingCO₂, water vapour, sulphur vapour, residual SO₂ and residual H₂S;(b) converting residual SO₂ in the first off-gas stream to H₂S in afirst off-gas treating reactor, thereby obtaining a second off-gasstream depleted in SO₂ and enriched in H₂S and CO₂ compared to the firstoff-gas stream;(c) contacting the second off-gas stream with an H₂S absorbing liquid,thereby transferring H₂S from the gas stream to the H₂S absorbing liquidto obtain H₂S absorbing liquid enriched in H₂S and a third off-gasstream enriched in CO₂;(d) removing CO₂ from the third off-gas stream by contacting the thirdoff-gas stream with CO₂ absorbing liquid in a CO₂ absorber, therebytransferring CO₂ from the third off-gas stream to the CO₂ absorbingliquid to obtain CO₂ absorbing liquid enriched in CO₂ and purified gas.

The purified gas, having very low concentrations of contaminants,especially CO₂, may be vented into the atmosphere in compliance withenvironmental standards. In addition, CO₂ may be recovered from the CO₂absorbing liquid enriched in CO₂, optionally pressurised and used forexample in enhanced oil recovery.

The process according to the invention is especially suitable for acidgas streams comprising significant amounts of CO₂ in addition to H₂S, asboth compounds are efficiently removed.

Suitably, the acid gas stream comprises in the range of from 5 to 95 vol%, preferably from 40 to 95 vol %, more preferably from 60 to 95 vol %of H₂S, based on the total acid gas stream.

Suitably, the acid gas stream comprises at least 1 vol %, preferably atleast 5 vol %, more preferably at least 10 vol % of CO₂, based on thetotal acid gas stream. These amounts of CO₂ in the acid gas stream willtranslate into comparable amounts of CO₂ in the third off-gas stream.

Preferably, the acid gas stream is obtained from the regeneration stepof a gas purification process. A gas purification process is required inorder to reduce the concentration of especially H₂S in industrial gasessuch as refinery gas, natural gas or synthesis gas, and generallyinvolves absorbing H₂S in liquid absorbent, which is subsequentlyregenerated to give H₂S-rich gases.

In step (a), H₂S in the acid gas stream is reacted with SO₂ to formsulphur vapour and water vapour, thereby obtaining a first off-gasstream comprising CO₂, water vapour, sulphur vapour, residual SO₂ andresidual H₂S.

Suitably, step (a) takes place in a Claus unit. In the Claus unit, partof the H₂S in the acid gas is partially oxidised using oxygen-containinggas (including pure oxygen) to form SO₂, followed by reaction of the SO₂formed with the remaining part of the H₂S in the presence of a Clauscatalyst, preferably non-promoted spherical activated alumina.

The Claus unit suitably comprises a combustion chamber followed by twoor more catalyst beds and two or more condensers. The reaction productsare cooled in these condensers and liquid elemental sulphur isrecovered. Since the yield of elemental sulphur is not quantitative, aminor amount of unreacted hydrogen sulphide and unreacted sulphurdioxide remains in the off-gases from the Claus unit. The off-gas fromthe Claus unit, which is the first off-gas stream, therefore stillcomprises residual SO₂ and residual H₂S. As the partial oxidation of H₂Sto SO₂ usually is done with air as oxygen-containing gas, a substantialamount of nitrogen will be present in all gas streams exiting the Clausunit. Thus, the first off-gas stream will also comprise a substantialamount of nitrogen besides the aforementioned components.

In step (b), the first off-gas stream is passed to a first off-gastreating reactor to remove residual SO₂. In the first off-gas treatingreactor SO₂ is reduced to H₂S in a hydrogenation reaction. Further, COS(if present) is converted to H₂S.

A preferred off-gas treating reactor is a so-called SCOT reactor, i.e.,Shell Claus Off-gas Treating reactor, as for example described in thewell-known textbook by Kohl and Riesenfeld, Gas Purification, 3rd ed.Gulf Publishing Co, Houston, 1979.

The temperature in the first off-gas treating reactor is suitably in therange of from 150 to 450° C., preferably from 180 to 250° C. At atemperature above 180° C., the presence of small amounts of elementalsulphur in the form of mist in the reaction off-gas is avoided, as thetemperature is now above the dew point of sulphur.

In the first off-gas treating reactor, preferably a Group VI and/orGroup VII metal catalyst supported on an inorganic carrier is used.Preferably, the catalyst comprises at least one metal selected from thegroup consisting of copper, cobalt, chromium, vanadium and molybdenum.The metal is suitably present on the catalyst in the form of its oxideor sulphide. The carrier can be selected from the group consisting ofalumina, silica, silica-alumina, titania, zirconia and magnesia.

A second off-gas stream, depleted in SO₂ and enriched in H₂S and CO₂compared to the first off-gas stream, is emitted from the first off-gastreating reactor.

Suitably, the second off-gas stream comprises less than 500 ppmv H₂S,preferably less than 200 ppmv, more less than 100 ppmv H₂S, based on thetotal second off-gas stream.

It will be understood that the amount of CO₂ in the second off-gasstream will depend on the amount of CO₂ in the first off-gas stream.Suitably, the amount of CO₂ in the second off-gas stream is in the rangeof 105 to 150% of the amount of CO₂ in the first off-gas stream.

In step (c), the second off-gas stream is contacted with an H₂Sabsorbing liquid, thereby transferring H₂S from the gas stream to theH₂S absorbing liquid to obtain H₂S absorbing liquid enriched in H₂S anda third off-gas stream enriched in CO₂.

Prior to being contacted with the H₂S absorbing liquid, the secondoff-gas stream is suitably cooled, preferably to a temperature in therange of from 6 to 60° C. More preferably, cooling is effected in twosteps, the first one being an indirect heat exchange and the second onea direct heat exchange with water.

A preferred H₂S absorbing liquid comprises a chemical solvent and/or aphysical solvent, suitably as an aqueous solution.

Suitable chemical solvents are primary, secondary and/or tertiaryamines, including sterically hindered amines.

A preferred chemical solvent comprises a secondary or tertiary amine,preferably an amine compound derived from ethanol amine, more especiallyDIPA, DEA, MMEA (monomethyl-ethanolamine), MDEA (methyldiethanolamine)TEA (triethanolamine), or DEMEA (diethyl-monoethanolamine), preferablyDIPA or MDEA. It is believed that these chemical solvents react withacidic compounds such as H₂S.

Step (c) is suitably performed in an absorption column, either a packedor a tray column may be used. In order to decrease the co-absorption ofCO₂, a relatively high gas velocity is applied. It is preferred to use agas velocity in the range of from 1.0 to 3.0 m/s. It is furtherpreferred to apply an absorption column having less than 20 absorptionlayers. For example, when using a tray column in step (c), the traycolumn preferably has less than 20 contacting valve trays. When using apacked column in step (c), the packed column preferably has less than 20theoretical plates. The use of an absorption zone having between 5 and15 absorption layers is particularly preferred in step (c).

After passage through the H₂S absorbing liquid in step (c), theunabsorbed part of the second off-gas stream, which now comprises asubstantial amount of CO₂, is discharged from the H₂S absorption columnas a third off-gas stream.

The invention is especially suitable in the event that the third off-gasstream comprises a relatively large amount of CO₂, preferably at least 1vol %, more preferably at least 5 vol %, still more preferably at least10 vol % and most preferably at least 20 vol % of CO₂, based on thetotal third off-gas stream.

It is an advantage of the process that the amount of sulphur compounds,especially SO₂, is very low. This enables the use of standard carbonsteel equipment for step (d), whereas for known CO₂ removal equipment,for example CO₂ removal from flue gases, expensive stainless steelequipment has to be used.

Furthermore, there is no need for a quench column, as the gas hasalready been quenched in step (c).

In step (d), CO₂ is removed from the third off-gas stream by contactingthe third off-gas stream with CO₂ absorbing liquid in a CO₂ absorber,thereby transferring CO₂ from the third off-gas stream to the CO₂absorbing liquid to obtain CO₂ absorbing liquid enriched in CO₂ andpurified gas.

Suitably, step (d) takes place at elevated pressure, and at relativelylow temperature. Elevated pressure means that the operating pressure ofthe CO₂ absorber is above ambient pressure. Preferably, step (d) takesplace at an operating pressure in the range of from 20 to 200 mbarg,more preferably from 50 to 150 mbarg. As the third off-gas stream isalready at elevated pressure, the pressure difference between the thirdoff-gas stream pressure and the operating pressure of the CO₂ absorberis relatively small. Thus, the third off-gas stream does not need to bepressurised or needs to be pressurised to a lesser extent prior toentering the CO₂ absorber. Given the large volume of gas to bepressurised, the use of a smaller pressurising equipment or eliminationof the need for pressurizing equipment altogether will result in aconsiderable cost-saving for the overall process.

The CO₂ absorbing liquid may be any absorbing liquid capable of removingCO₂ from a gas stream. Such CO₂ absorbing liquids may include chemicaland physical solvents or combinations of these.

Suitable physical solvents include dimethylether compounds ofpolyethylene glycol.

Suitable chemical solvents include ammonia and amine compounds.

In one embodiment, the CO₂ absorbing liquid comprises one or more aminesselected from the group of monethanolamine (MEA), diethanolamine (DEA),diglycolamine (DGA), methyldiethanolamine (MDEA) and triethanolamine(TEA). MEA is an especially preferred amine, due to its ability toabsorb a relatively high percentage of CO₂ (volume CO₂ per volume MEA).Thus, an absorbing liquid comprising MEA is suitable to remove CO₂ fromthird off-gas streams having low concentrations of CO₂, typically 3-10volume % CO₂.

In another embodiment, the CO₂ absorbing liquid comprises one or moreamines selected from the group of methyldiethanolamine (MDEA),triethanolamine (TEA), N,N′-di(hydroxyalkyl)piperazine,N,N,N′,N′-tetrakis(hydroxyalkyl)-1,6-hexanediamine and tertiaryalkylamine sulfonic acid compounds.

Preferably, the N,N′-di(hydroxyalkyl)piperazine isN,N′-d-(2-hydroxyethyl)piperazine and/orN,N′-di-(3-hydroxypropyl)piperazine.

Preferably, the tetrakis(hydroxyalkyl)-1,6-hexanediamine isN,N,N′,N′-tetrakis(2-hydroxyethyl)-1,6-hexanediamine and/orN,N,N′,N′-tetrakis(2-hydroxypropyl)-1,6-hexanediamine.

Preferably, the tertiary alkylamine sulfonic compounds are selected fromthe group of 4-(2-hydroxyethyl)-1-piperazineethanesulfonic acid,4-(2-hydroxyethyl)-1-piperazinepropanesulfonic acid,4-(2-hydroxyethyl)piperazine-1-(2-hydroxypropanesulfonic acid) and1,4-piperazinedi(sulfonic acid).

In an especially preferred embodiment, the CO₂ absorbing liquidcomprises a combination of amines, the combination being one of moreamines selected from the group of monethanolamine (MEA), diethanolamine(DEA), diglycolamine (DGA), methyldiethanolamine (MDEA) andtriethanolamine (TEA) in combination with one of more amines selectedfrom the group of N,N′-di(hydroxyalkyl)piperazine,N,N,N′,N′-tetrakis(hydroxyalkyl)-1,6-hexanediamine and tertiaryalkylamine sulfonic acid compounds.

The CO₂ absorbing liquid may further comprise N-ethyldiethanolamine(EDEA) and/or piperazine, especially in combination with one of moreamines selected from the group of monethanolamine (MEA), diethanolamine(DEA), diglycolamine (DGA), methyldiethanolamine (MDEA) andtriethanolamine (TEA).

In another preferred embodiment, the CO₂ absorbing liquid comprisesammonia.

Suitably, the amount of oxygen in the third off-gas stream is very low.Oxygen can cause amine degradation and can lead to the formation ofdegradation products in the absorbing liquid. A lower oxygen content ofthe third off-gas stream will therefore result in less amine degradationand less formation of degradation products.

In the event that the third off-gas stream comprises an appreciablequantity of oxygen, suitably in the range of from 1 to 20% (v/v) ofoxygen, preferably a corrosion inhibitor is added to the absorbingliquid. Suitable corrosion inhibitors are described for example in U.S.Pat. No. 6,036,888.

The purified gas obtained in step (d) comprises very little CO₂.Suitably, the purified gas comprises less than 0.5 vol %, preferablyless than 0.1 vol % and more preferably less than 0.01 vol % of CO₂. Thepurified gas may be vented into the atmosphere of incinerated.

In most cases it will be desirable to have a continuous process,including regeneration of the CO₂ absorbing liquid. Thus, preferably theprocess further comprises the step of regenerating the CO₂ absorbingliquid enriched in CO₂ by contacting the absorbing liquid enriched inCO₂ with a stripping gas at elevated temperature in a regenerator toobtain regenerated absorbing liquid and a gas stream enriched in CO₂. Itwill be understood that the conditions used for regeneration dependinter alia on the type of absorbing liquid and on the conditions used inthe absorption step. Suitably, regeneration takes place at a differenttemperature and/or different pressure than the absorption.

In the event that the CO₂ absorbing liquid comprises an amine, preferredregeneration temperatures are in the range of from 100 to 200° C. In theevent that the CO₂ absorbing liquid comprises an aqueous amine,regeneration preferably takes place at pressure in the range of from 1to 5 bara.

In the event that the CO₂ absorbing liquid comprises ammonia, suitablythe absorbing step is performed at temperatures below ambienttemperature, preferably in the range of from 0 to 10° C., morepreferably from 2 to 8° C.

The regeneration step is suitably performed at temperatures higher thanused in the absorption step. When using a CO₂ absorbing liquidcomprising ammonia, the CO₂-enriched gas stream exiting the regeneratoris at elevated pressure. Suitably, the pressure of the CO₂-enriched gasstream is in the range of from 5 to 8 bara, preferably from 6 to 8 bara.In applications where the CO₂-enriched gas stream needs to be at a highpressure, for example when it will be used for injection into asubterranean formation, it is an advantage that the CO₂-enriched gasstream is already at an elevated pressure. Normally, a series ofcompressors is needed to pressurise the CO₂-enriched gas stream to thedesired high pressures. A CO₂-enriched gas stream which is already atelevated pressure is easier to further pressurise.

Preferably, the gas stream enriched in carbon dioxide is pressurised toproduce a pressurised carbon dioxide stream.

Preferably, the pressurised CO₂ stream has a pressure in the range offrom 40 to 300 bara, more preferably from 50 to 300 bara. A CO₂ streamhaving a pressure in these preferred ranges can be used for manypurposes, in particular for enhanced recovery of oil, coal bed methaneor for sequestration in a subterranean formation.

Especially for purposes wherein the pressurised CO₂ stream is injectedinto a subterranean formation, high pressures are required. In apreferred embodiment, the pressurised CO₂ stream is used for enhancedoil recovery. By injecting CO₂ into an oil reservoir, the oil recoveryrate can be increased. Typically, the pressurised CO₂ stream is injectedinto the oil reservoir, where it will be mixed with some of the oilwhich is present. The mixture of CO₂ and oil will displace oil whichcannot be displaced by traditional injections.

1. A process for removal of H₂S and CO₂ from an acid gas streamcomprising H₂S and CO₂, the process comprising the steps of: (a)reacting H₂S in the acid gas stream with SO₂ to form sulphur vapour andwater vapour, thereby obtaining a first off-gas stream comprising CO₂,water vapour, sulphur vapour, residual SO₂ and residual H₂S; (b)converting residual SO₂ in the first off-gas stream to H₂S in a firstoff-gas treating reactor, thereby obtaining a second off-gas streamdepleted in SO₂ and enriched in H₂S and CO₂ compared to the firstoff-gas stream; (c) contacting the second off-gas stream with an H₂Sabsorbing liquid, thereby transferring H₂S from the gas stream to theH₂S absorbing liquid to obtain H₂S absorbing liquid enriched in H₂S anda third off-gas stream enriched in CO₂; and (d) removing CO₂ from thethird off-gas stream by contacting the third off-gas stream with CO₂absorbing liquid in a CO₂ absorber, thereby transferring CO₂ from thethird off-gas stream to the CO₂ absorbing liquid to obtain CO₂ absorbingliquid enriched in CO₂ and purified gas.
 2. A process according to claim1, wherein the CO₂ absorbing liquid comprises one or more amines,selected from the group of monethanolamine (MEA), diethanolamine (DEA),diglycolamine (DGA), methyldiethanolamine (MDEA) and triethanolamine(TEA).
 3. A process according to claim 1, wherein the CO₂ absorbingliquid comprises a combination of amines, the combination being one ofmore amines selected from the group of monethanolamine (MEA),diethanolamine (DEA), diglycolamine (DGA), methyldiethanolamine (MDEA)and triethanolamine (TEA) in combination with one of more aminesselected from the group of N,N′-di(hydroxyalkyl)piperazine,N,N,N′,N′-tetrakis(hydroxyalkyl)-1,6-hexanediamine and tertiaryalkylamine sulfonic acid compounds.
 4. A process according to claim 1,wherein the CO₂ absorbing liquid comprises N-ethyldiethanolamine (EDEA)and/or piperazine, especially in combination with one of more aminesselected from the group of monethanolamine (MEA), diethanolamine (DEA),diglycolamine (DGA), methyldiethanolamine (MDEA) and triethanolamine(TEA)
 5. A process according to claim 1, wherein the CO₂ absorbingliquid comprises ammonia.
 6. A process according to claim 1, wherein thefeed acid gas stream is obtained by separating H₂S and CO₂ from a sourgas, preferably sour natural gas.
 7. A process according to claim 1,wherein the third off-gas stream comprises at least 1 vol of CO₂, basedon the total third off-gas stream.
 8. A process according to claim 1,the process further comprising the step of: (d) regenerating theabsorbing liquid enriched in CO₂ by contacting the absorbing liquidenriched in CO₂ with a stripping gas at elevated temperature in aregenerator to obtain regenerated absorbing liquid and a gas streamenriched in CO₂.
 9. A process according to claim 8, the process furthercomprising the step of: (d) pressurising the gas stream enriched in CO₂.10. A process according to claim 9, wherein the pressurised gas streamenriched in CO₂ is used for enhanced oil recovery.